Drilling fluid composition containing treated date pit particles and methods of use thereof

ABSTRACT

A drilling fluid composition including a viscosifier, treated date pit particles which are i) de-oiled and ii) treated with a base or both a base and an acid, and an aqueous base fluid, wherein the treated date pit particles are present in an amount of 0.01-5 wt %, relative to a total weight of the drilling fluid composition. A method of making the drilling fluid composition by de-oiling date pit particles, treating with a base or a base and an acid in a freeze/thaw process, and adding the freeze/thaw mixture to the viscosifier and the aqueous base fluid. A process for drilling a subterranean geological formation with the drilling fluid composition.

STATEMENT REGARDING PRIOR DISCLOSURE BY THE INVENTORS

Aspects of this technology are described in Jimoh K. Adewole, Musa O.Najimu, “Oil Field Chemicals from Macromolecular Renewable Resources:Date Pit As a Case Study for Drilling Fluid Additive”, AIChE AnnualMeeting, Minneapolis Minn., Nov. 3, 2017, which is incorporated hereinby reference in its entirety.

BACKGROUND OF THE INVENTION Technical Field

The present invention relates to a drilling fluid composition thatcontains treated date pit particles as a rheological modifier, a densityreducing agent, and a filtration control agent, and methods of makingand using the same.

Description of the Related Art

The “background” description provided herein is for the purpose ofgenerally presenting the context of the disclosure. Work of thepresently named inventors, to the extent it is described in thisbackground section, as well as aspects of the description which may nototherwise qualify as prior art at the time of filing, are neitherexpressly or impliedly admitted as prior art against the presentinvention.

Drilling fluid plays an important role in the successful drilling andcompletion of oil wells. The cost of drilling fluid is a majorcontributor to the overall cost of oil production. For this reason,research efforts have focused on developing cheap drilling fluidmaterials to reduce the cost of drilling.

Drilling fluids are mixtures of several chemical components that areused for a variety of purposes in drilling operations, such as fluidloss prevention, to provide stability under various operatingtemperatures and pressures, to provide stability against corrosion,flow, lubricity, electrical conductivity, alkalinity and pH control[Caenn, R., H. C. H. Darley, and G. R. Gray, Chapter 1—Introduction toDrilling Fluids, in Composition and Properties of Drilling andCompletion Fluids (Sixth Edition), 2011, Gulf Professional Publishing:Boston. p. 1-37]. Synthetic as well as natural polymeric additives arecommon additives to fulfill these property requirements. Environmentalregulations have encouraged drilling contractors to employ the use ofrenewable non-hazardous additives [Hermoso, J., F. Martinez-Boza, and C.Gallegos, Influence of aqueous phase volume fraction, organoclayconcentration and pressure on invert-emulsion oil muds rheology. Journalof Industrial and Engineering Chemistry, 2015, 22: p. 341-349]. Naturalpolymers offer several advantages compared to synthetic polymers due totheir economic impact, compatibility with many mud systems irrespectiveof water hardness, salinity and pH range, abundance, and environmentalfriendliness. Raw materials for producing natural polymers come fromplants and agricultural products, and hence they are cheap andabundantly available.

Overbalanced drilling (OBD) is a well-known drilling method in the oiland gas industries, which involves maintaining a pressure in thewellbore that is higher than the static pressure of the formation beingdrilled. Using this technique, drilling mud is forced into theformation, which often leads to a decrease in the ability of theformation to transmit oil into the wellbore at a given pressure and flowrate. In underbalanced drilling (UBD), the pressure in the wellbore iskept lower than the static pressure of the formation being drilled.Thus, formation fluid flows into the wellbore and up to the surfaceunlike overbalanced drilling methods. The common practice is to separatethe produced fluids at the surface. For this reason, UBD is a moreexpensive than OBD methods, and thus low-cost drilling fluids are neededto help offset these expenses.

Underbalanced wells have other advantages including the elimination offormation damage, increased rate of penetration due to less pressure atthe bottom of the wellbore which makes it easier for the drill bit tocut and remove rock, and reduction in fluid loss [Steve, N.,Underbalanced Drilling, in Petroleum Engineering Handbook, L. W. Lake,Editor, 2006, Society of Petroleum Engineers: Richardson]. Also, duringunderbalanced drilling operations, maintaining an underbalanced stateuntil the well becomes productive can help to prevent drilling mudinvasion into the formation. Consequently, formation damage can becompletely avoided and lost circulation can be reduced.

In view of the forgoing, there is a need for drilling fluid compositionsthat can be tuned and used in different drilling operations (e.g., OBDand UBD) that include cheap, natural, readily available additives forcontrol over fluid loss, density reduction, rheological properties, andcorrosion prevention properties of the drilling fluids.

BRIEF SUMMARY OF THE INVENTION

Accordingly, it is one object of the present invention to provide noveldrilling fluid compositions which include treated date pit particles andwhich have superior fluid loss, density reduction, rheologicalproperties, and corrosion prevention properties.

It is another object of the present invention to provide novel methodsof making the drilling fluid compositions.

It is another object of the present invention to provide novel processesof drilling subterranean geological formations using the drilling fluidcompositions.

These and other objects, which will become apparent during the followingdetailed description, have been achieved by the inventors' discoverythat treated date pit particles can be used as drilling fluid additivesto bestow advantageous fluid loss, density reduction, and rheologicalproperties to the resulting drilling fluids, and that these propertiescan be tuned by selection of a date pit particle treatment process forapplication in various drilling operations.

Therefore, according to a first aspect, the present disclosure relatesto a drilling fluid composition that includes a) a viscosifier, b)treated date pit particles, which are i) de-oiled and ii) treated with abase or both a base and an acid, and c) an aqueous base fluid, whereinthe treated date pit particles are present in an amount of 0.01-5 wt %,relative to a total weight of the drilling fluid composition.

In some embodiments, the viscosifier is bentonite.

In some embodiments, the viscosifier is present in an amount of 1-10 wt%, relative to a total weight of the drilling fluid composition.

In some embodiments, the treated date pit particles are ii) treated witha base. In some embodiments, the base is sodium hydroxide.

In some embodiments, the drilling fluid composition has a filtrationwater loss volume of 15-28 mL after 30 min under a pressure of 100 psi.

In some embodiments, the treated date pit particles are ii) treated withboth a base and an acid. In some embodiments, the base is sodiumhydroxide and the acid is acetic acid or sulfuric acid.

In some embodiments, the drilling fluid composition has a filtrationwater loss volume of 30-40 mL after 30 min under a pressure of 100 psi.

In some embodiments, the drilling fluid composition has a density of6.5-8.5 lb/gal.

In some embodiments, the drilling fluid composition has a plasticviscosity of 3.0-3.5 cP.

In some embodiments, the drilling fluid composition further includes atleast one additive selected from the group consisting of an antiscalant,a thickener, a deflocculant, a lubricant, a buffer, a biocide, and aweighting agent.

In some embodiments, the drilling fluid composition is substantiallyfree of a fluid loss additive, a density reducing agent, and a rheologymodifying agent, other than the treated date pit particles and theviscosifier.

According to a second aspect, the present disclosure relates to a methodof making the drilling fluid composition, involving a) contacting drieddate pit particles with an organic solvent to remove oils and formde-oiled date pit particles, b) mixing the de-oiled date pit particleswith a base and water to form an alkaline mixture, c) subjecting thealkaline mixture to a freeze/thaw process and optionally adding an acidto form a freeze/thaw mixture comprising the treated date pit particlesin water, and d) adding the freeze/thaw mixture to the viscosifier andthe aqueous base fluid to form the drilling fluid composition.

In some embodiments, the organic solvent is at least one selected fromthe group consisting of pentane, hexane, methanol, and ethanol.

In some embodiments, the base is sodium hydroxide and the acid, whenadded, is acetic acid or sulfuric acid.

In some embodiments, the freeze/thaw process includes subjecting thealkaline mixture to a temperature of −20° C. or below for at least 4hours to form a frozen mixture, thawing the frozen mixture at atemperature of 20-50° C., and agitating for at least 15 minutes to formthe freeze/thaw mixture.

According to a third aspect, the present disclosure relates to a processfor drilling a subterranean geological formation, involving drilling thesubterranean geological formation with a drill bit to form a wellbore,and injecting the drilling fluid composition into the subterraneangeological formation through the wellbore.

In some embodiments, the treated date pit particles are ii) treated witha base, and the drilling fluid composition is injected into thesubterranean geological formation through the wellbore to maintain apressure in the wellbore that is higher than a static pressure of thesubterranean geological formation.

In some embodiments, the treated date pit particles are ii) treated withboth a base and an acid, and the drilling fluid composition is injectedinto the subterranean geological formation through the wellbore tomaintain a pressure in the wellbore that is lower than a static pressureof the subterranean geological formation.

The foregoing paragraphs have been provided by way of generalintroduction, and are not intended to limit the scope of the followingclaims. The described embodiments, together with further advantages,will be best understood by reference to the following detaileddescription.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete appreciation of the disclosure and many of the attendantadvantages thereof will be readily obtained as the same becomes betterunderstood by reference to the following detailed description whenconsidered in connection with the accompanying drawings, wherein:

FIG. 1 is a FTIR spectrum indicating the change in chemical compositionof date pit samples before and after treatment.

DETAILED DESCRIPTION OF THE EMBODIMENTS

Embodiments of the present disclosure will now be described more fullyhereinafter with reference to the accompanying drawings, in which some,but not all of the embodiments of the disclosure are shown.

As used herein, the words “a” and “an” and the like carry the meaning of“one or more”. Additionally, within the description of this disclosure,where a numerical limit or range is stated, the endpoints are includedunless stated otherwise. Also, all values and subranges within anumerical limit or range are specifically included as if explicitlywritten out.

As used herein, the terms “optional” or “optionally” means that thesubsequently described event(s) can or cannot occur or the subsequentlydescribed component(s) may or may not be present (e.g. 0 wt %).

When referencing drilling fluid compositions, the phrase “substantiallyfree”, unless otherwise specified, describes an amount of a particularcomponent (e.g., fluid loss additive) being less than about 1 wt. %,preferably less than about 0.5 wt. %, preferably less than about 0.1 wt.%, preferably less than about 0.01 wt. %, preferably less than about0.001 wt. %, preferably 0 wt. %, relative to a total weight of thedrilling fluid composition.

The term “comprising” is considered an open-ended term synonymous withterms such as including, containing or having and is used herein todescribe aspects of the invention which may include additionalcomponents, functionality and/or structure. Terms such as “consistingessentially of” are used to identify aspects of the invention whichexclude particular components that are not explicitly recited in theclaim but would otherwise have a material effect on the basic and novelproperties of the drilling fluid composition. The term “consisting of”describes aspects of the invention in which only those featuresexplicitly recited in the claims are included and thus other componentsnot explicitly or inherently included in the claim are excluded.

When referencing “treated date pit particles” herein, the term “treated”(or “chemically modified” (CM) or “modified”) refers to chemicalmodification of date pit particles, by use of a base or a base and anacid in a freeze/thaw process, prior to mixing the date pit particleswith other components to form a drilling fluid. Therefore, unless statedotherwise, the term “treated” is different from adding an acid or a baseto an already formulated drilling fluid containing date pit particles,for example, to adjust the pH of the drilling fluid or to modify aplurality of components present in the already formulated drillingfluid.

The term “seed” or “pit” as used herein refers to any portion of theseed/pit, including the whole pit (i.e., the pit is used in itsentirety), or any portion of the pit (e.g., the exterior shell of thepit), preferably the whole pit.

As used herein, the term “fatty” describes a long-chain hydrophobicportion of a compound made up of hydrogen and anywhere from 6 to 26carbon atoms, which may be fully saturated or partially unsaturated, andoptionally attached to a functional group such as a hydroxyl group or acarboxyl group. Fatty alcohols, fatty acids, fatty esters, fatty amides,and fatty hydrocarbon oils are examples of materials which contain afatty portion.

Drilling Fluid Composition

Drilling fluids, also known as drilling muds, have many uses duringdrilling operations to tap underground collections of oil and gas. Themain functions are to suspend and release cuttings, to assist in theremoval of cuttings from the well, to seal off unwanted formations whichmay be encountered at different levels preventing the loss of drillingfluids to void spaces/porous formations, to lubricate the drilling tool,to control formation pressures, to assist formation fracking, tomaintain the wellbore pressure and stability of the bore hole, tominimize formation damage, to transfer hydraulic energy to tools/bit, toensure adequate formation evaluation (e.g., logging), and/or tofacilitate cementing and completion. The drilling fluid compositions ofthe present disclosure can be advantageously formulated to possessrheological properties that enable their use in one or more of theseapplications depending on the specific needs of a drilling process. Thedrilling fluids herein are preferably useful for more than one of theseapplications, and are thus considered to be multi-functional.

The inventors have discovered a water-based drilling fluid whichutilizes a readily available additive, i.e., date pit particulates,which are often considered an agricultural waste byproduct, useful forcontrol of fluid loss, density reduction, modification of drilling fluidrheological properties, and corrosion prevention in various drillingapplications. Such properties bestowed to the resulting drilling fluidscan be easily tuned by selection of an appropriate date pit particletreatment process, to provide drilling fluids useful in overbalanceddrilling (OBD) or underbalanced drilling (UBD) operations, as well ascompletion fluid operations. The drilling fluid composition of thepresent disclosure thus generally comprises, consists essentially of, orconsists of a) a viscosifier, b) treated date pit particles, which arei) de-oiled and ii) treated with a base or both a base and an acid, andc) an aqueous base fluid.

Viscosifier

Viscosifiers may be included in the present drilling fluid to helpmodulate the rheological properties and to help improve thehole-cleaning, tool lubricating capability, solids-suspensioncapabilities of the drilling fluids, and/or to aid in the formation ofmud cake to curtail drilling fluid invasion. In preferred embodiments,the viscosifier forms drilling fluids which are thixotropic, and thusare free-flowing, thin, less viscous when agitated, flowed, or otherwisestressed (time dependent shear thinning), but are thick or viscous andresistant to flow under static conditions such as when pumping isstopped. The viscosifier is preferably employed in an amount of 1-10 wt%, preferably 2-9 wt %, preferably 3-8 wt/o, preferably 4-7 wt %,preferably 5-6 wt %, relative to a total weight of the drilling fluidcomposition, although amounts outside of these ranges may be used whendrilling fluids having higher or lower viscosity are needed.

Exemplary viscosifiers that can be used herein include, but are notlimited to, bauxite, bentonite, dolomite, limestone, calcite, vaterite,aragonite, magnesite, taconite, gypsum, quartz, marble, hematite,limonite, magnetite, andesite, garnet, basalt, dacite, nesosilicates ororthosilicates, sorosilicates, cyclosilicates, inosilicates,phyllosilicates, tectosilicates, kaolins, montmorillonite, fullersearth, and halloysite and the like, as well as mixtures thereof. Naturalpolymers, such as xanthan gum (XC), psyllium husk powder (PHP),hydroxyethyl cellulose (HEC), carboxymethylcellulose, and polyanioniccellulose (PAC), as well as synthetic polymers, such as poly(diallylamine), diallyl ketone, diallyl amine, styryl sulfonate, vinyl lactam,laponite, and polygorskites (e.g. attapulgite, sepiolite), includingmixtures thereof, may also be used as viscosifiers.

Preferably, the viscosifier is bentonite, and more preferably, no otherviscosifier is present besides bentonite (i.e., the viscosifier consistsof bentonite). Bentonite is an absorbent aluminum phyllosilicate, impureclay made primarily of montmorillonite. Montmorillonite generallycomprises sodium, calcium, aluminum, magnesium, and silicon, and oxidesand hydrates thereof. Other compounds may also be present in thebentonite of the present disclosure, including, but not limited to,potassium-containing compounds, and iron-containing compounds. There aredifferent types of bentonite, named for the respective dominant element,such as potassium (K), sodium (Na), calcium (Ca) and aluminum (Al).Therefore, in terms of the present disclosure “bentonite” may refer topotassium bentonite, sodium bentonite, calcium bentonite, aluminumbentonite, and mixtures thereof, depending on the relative amounts ofpotassium, sodium, calcium, and aluminum in the bentonite. In preferredembodiments where bentonite is present, said drilling fluids areconsidered to be clay-containing drilling fluids.

Treated Date Pit Particles

Date palm is a flowering plant species in the palm family, Arecaceae,cultivated for its edible sweet fruit known as a “date”, which is awell-known staple food in North Africa, the Middle East and many otherlocations. The date pit (also called date seed) is an integral part ofthe date fruit, accounting for roughly 6-14 wt % of the total weight ofthe weight fruit. Date pits are often considered a waste byproduct ofthe date fruit, although sometimes they can be ground as used for animalfeed. Date pits generally have the following composition: 5-15 wt %water (or 0.01-5 wt % water after drying), 0.5-2 wt % ash, 70-88 wt %carbohydrates (mainly hemicellulose, lignin, and cellulose), 2-8 wt %crude proteins, and 5-15 wt % fat content (i.e., fatty materials such aslipids, fatty esters, etc.), each relative to a total weight of the datepit. A typical date pit composition is provided in Table 1 (see Adewole,J. K. and A. S. Sultan, A Study on Processing and Chemical Compositionof Date Pit Powder for Application in Enhanced Oil Recovery. Defect andDiffusion Forum, 2014. 353: p. 79-83—incorporated herein by reference inits entirety). In addition, date pits also typically contain 0.56-5.4 wt% lauric acid.

TABLE 1 Average Composition of Date Seeds Components Contents (wt %)Moisture 10.20  Ash 1.18 Carbohydrate 72.59-86.89, Crude Proteins 5.67Fat Contents  5.02-12.67

Few research works have been published on the use of date pit asdrilling fluid additive [Amanullah, M., et al., Application of anindigenous eco-friendly raw material as fluid loss additive. Journal ofPetroleum Science and Engineering, 2016, 139: p. 191-197—incorporatedherein by reference in its entirety], and none disclose the use oftreated date pit particles. It has also been reported that date pit haveexcellent corrosion inhibiting properties both in the alkaline andacidic medium [Umoren, S. A., Z. M. Gasem, and I. B. Obot, NaturalProducts for Material Protection: Inhibition of Mild Steel Corrosion byDate Palm Seed Extracts in Acidic Media. Industrial & EngineeringChemistry Research, 2013, 52(42): p. 14855-14865; Gerengi, H.,Anticorrosive Properties of Date Palm (Phoenix dactylifera L.) FruitJuice on 7075 Type Aluminum Alloy in 3.5% NaCl Solution. Industrial &Engineering Chemistry Research, 2012, 51(39): p. 12835-12843—eachincorporated herein by reference in its entirety].

Date pit particles are formed by grinding date pits which have beenpreferably washed with water and dried. While the date pits can beground to various sizes useful for making the drilling fluidcompositions herein, typically the date pit particles have a largestdimension of less than 500 μm, preferably less than 400 μm, preferablyless than 300 μm, preferably less than 200 μm, preferably 0.1-150 μm,preferably 0.5-100 μm, preferably 1-75 μm, preferably 3-50 μm,preferably 5-40 μm, preferably 10-30 μm. Further, the date pit particlesmay be ground to any measure of roundness (i.e., very angular: cornerssharp and jagged, angular, sub-angular, sub-rounded, rounded, orwell-rounded: corners completely rounded) using visual inspectionsimilar to characterization used in the Shepard and Young comparisonchart, preferably the date pit particles are ground to a sub-angular,sub-rounded, or well-rounded roundness.

Date pit particles are categorized herein based upon the treatmentmethod used during their manufacture, for example: Non-de-oiled date pitparticles (ND) are date pit particles which have not been chemicallytreated or modified other than being washed with water, dried, andground into particulates; De-oiled date pit particles (DO) are date pitparticles which have been i) de-oiled; Treated date pit particles(chemically modified, CM) are date pit particles which have been both i)de-oiled and ii) treated with a base or both a base and an acid. Any ofthe above date pit particles can be employed in the present drillingfluids, however, de-oiled or treated date pit particles are preferablyused, most preferably treated date pit particles are used. In preferredembodiments, date pit particles, preferably treated date pit particles,are present in the drilling fluid composition in an amount of 0.001-5 wt%, 0.01-4.5 wt %, preferably 0.05-4 wt %, preferably 0.1-3 wt %,preferably 0.2-2.5 wt %, preferably 1-2 wt %, relative to a total weightof the drilling fluid composition.

As will become evident, date pit particles which have been subject todifferent treatment regimens have differing chemical compositions andalso perform differently in drilling fluid compositions, thus providingdrilling fluids with differing properties, and in some cases, drillingfluids which can be used for completely different drilling applications.

For example, non-de-oiled date pit particles have a compositionsubstantially the same to the aforementioned date pit composition,albeit with a 0.01-5 wt %, preferably 0.1-4 wt %/o, more preferably 1-3wt % water content (after drying), relative to a total weight of thenon-de-oiled date pit particles.

De-oiled date pit particles have a lower fat content than non-de-oileddate pit particles since some or most fatty materials are removed duringthe de-oiling process to provide a fat content of less than 5 wt %,preferably less than 4 wt %, preferably less than 3 wt %, preferablyless than 2 wt %, preferably less than 1 wt %, preferably less than 0.5wt %, preferably about 0 wt %, relative to a total weight of thede-oiled date pit particles. Preferably, de-oiled date pit particleshave a lower content of fatty esters and fatty hydrocarbon oils, and mayhave a lower content of fatty alcohols, fatty acids, and fatty amidescompared to non-de-oiled date pit particles. Exemplary fatty alcoholsinclude 1-hexanol, 3-methyl-3-pentanol, 1-heptanol, 1-octanol,pelargonic alcohol, 1-decanol, undecyl alcohol, lauryl alcohol, tridecylalcohol, myristyl alcohol, pentadecyl alcohol, cetyl alcohol,palmitoleyl alcohol, heptadecyl alcohol, stearyl alcohol, oleyl alcohol,nonadecyl alcohol, arachidyl alcohol, heneicosyl alcohol, behenylalcohol, erucyl alcohol, lignoceryl alcohol, ceryl alcohol. Fatty acidsmay include, but are not limited to, caprylic acid, capric acid, lauricacid, myristic acid, palmitic acid, stearic acid, arachidic acid,behenic acid, lignoceric acid, cerotic acid, myristoleic acid,palmitoleic acid, sapienic acid, oleic acid, elaidic acid, vaccenicacid, linoleic acid, linoelaidic acid, α-inolenic acid, arachidonicacid, eicosapentaenoic acid, erucic acid, and docosahexaenoic acid.Fatty hydrocarbon oils include saturated and unsaturated dodecane,saturated and unsaturated tridecane, saturated and unsaturatedtetradecane, saturated and unsaturated pentadecane, saturated andunsaturated hexadecane, and the like, including branched-chain isomersof these compounds. Exemplary fatty esters are characterized by havingat least one fatty aliphatic chain derived from a fatty acid, a fattyalcohol, or both. Fatty esters herein may be monoesters of the formulaR¹COOR² in which at least one of R¹ and R² is an alkyl or alkenylradical having 6 to 26 carbon atoms, preferably 7 to 24 carbon atoms,more preferably 8 to 22 carbon atoms, even more preferably 9 to 20carbon atoms, yet even more preferably 10 to 18 carbon atoms, and wherethe sum of carbon atoms combined in R¹ and R² is from 7 to 52 carbonatoms, for example, cetyl octanoate and lauryl lactate. Diesters andtriesters containing at least one fatty aliphatic portion are alsoconsidered to be fatty esters, for example, mono-, di-, andtri-glycerides, more specifically the mono-, di-, and tri-esters ofglycerol and at least one fatty acid, for example, glyceryl mono-, di-,or tri-stearate, and palm stearin.

The comparative FTIR spectrum of FIG. 1 illustrates the chemicaldifferences between the non-de-oiled date pit particles and the de-oileddate pit particles, for example, the de-oiled date pit particles haveless IR absorption in the 1,000-1,500 cm⁻¹ (e.g., ether, alkane) and2,800-3,100 (e.g., aromatic) regions. Indeed, de-oiled date pitparticles have a minimum peak % transmission of greater than 75%,preferably greater than 80%, preferably greater than 82% in the1,000-1,500 cm⁻¹ range and a minimum peak % transmission of greater than95%, preferably greater than 97%, preferably greater than 99% in the2,800-3,100 region. In comparison, non-de-oiled date pit particles havea minimum peak % transmission in the 1,000-1,500 cm⁻¹ and 2,800-3,100regions of 55-65% and 80-90%, respectively.

Treated date pit particles, that is, date pit particles which have beenboth i) de-oiled and ii) treated with a base or both a base and an acidhave a higher content of polar functional groups including, but notlimited to, carboxylic acids, alcohols, and amines, compared to de-oileddate pit particles, likely owing to the cleavage of ester and amidebonds present in the date pits to form respective carboxylic acids,alcohols, and amines. For example, a total ester content in treated datepit particles is lower than the starting de-oiled date pit particles dueat least in part to hydrolytic conversion of ester functionality intocarboxylates and alcohols. The comparative FTIR spectrum of FIG. 1illustrates the chemical differences between the treated date pitparticles which have been ii) treated with a base, and the de-oiled datepit particles, for example, the treated date pit particles have agreater IR absorption in the 3,100-3,800 cm⁻¹ (e.g., O—H, N—H) regioncompared to the same IR region of both non-de-oiled and de-oiled datepit particles. Indeed, treated date pit particles have a minimum peak %transmission of 40-75%, preferably 50-70%, preferably 55-60% in the3,100-3,800 cm⁻¹ range, compared to a minimum peak % transmission of82-90% for non-de-oiled date pit particles and 90-98% transmission forde-oiled date pit particles in the 3,100-3,800 cm⁻¹ range, respectively.

In addition to the chemical differences between the various types ofdate pit particles (i.e., non-de-oiled date pit particles, de-oiled datepit particles, or treated date pit particles) the choice of date pitparticles also influences the fluid loss, density reduction, fluidrheology, and corrosion properties when used as a component of drillingfluids. Thus, selection of an appropriate date pit treatment method canprovide drilling fluids which are tuned to suit a particularapplication, such as, for example, overbalanced drilling (OBD),underbalanced drilling (UBD), and/or completion fluid operations.

In some embodiments, the drilling fluid compositions contain appropriateamounts of treated date pit particles, which are i) de-oiled and ii)treated with a base. Such drilling fluids preferably have a filtrationwater loss volume of 15-28 mL, preferably 16-27.8 mL, preferably 17-27mL, preferably 18-26 mL, preferably 20-25 mL after 30 min under apressure of 100 psi according to American Petroleum Institute (API)standard 13B-1 (ANSI/API 13B-1/ISO 10414-1). Further, such drillingfluid compositions have a filter cake thickness of 0.04-0.05 in,preferably 0.045-0.0499 in, preferably 0.048-0.0498 in per API standardprocedure 13B-1 (ANSI/API 13B-1/ISO 10414-1). In contrast, comparativedrilling fluids that include de-oiled date pit particles (i.e., nottreated with a base) have a filtration water loss volume of 28.1-29.6 mLafter 30 min under a pressure of 100 psi according to the same standard(API 13B-1). Therefore, treating de-oiled date pit particles with a basesuch as sodium hydroxide unexpectedly lowers the filtration water lossvolume (mL) of the drilling fluid composition by 6-21%, preferably7-20%, preferably 8-18% compared to a drilling fluid composition thatutilizes de-oiled date pit particles but is otherwise substantially thesame. Drilling fluids having such low filtration water loss volumes areparticularly advantageous for overbalanced drilling (OBD) operations.

In some embodiments, the drilling fluid compositions contain appropriateamounts of treated date pit particles, which are i) de-oiled and ii)treated with a base and an acid. Such drilling fluids preferably have afiltration water loss volume of 30-40 mL, preferably 31-38 mL,preferably 32-37 mL, preferably 33-36 mL, preferably 34-35 mL after 30min under a pressure of 100 psi according to American PetroleumInstitute (API) standard procedure 13B-1 (ANSI/API 13B-1/ISO 10414-1).In contrast, comparative drilling fluids that include de-oiled date pitparticles (i.e., not treated with a base) have a filtration water lossvolume of 28.1-29.6 mL after 30 min under a pressure of 100 psiaccording to the same standard (API 13B-1). Therefore, treating de-oileddate pit particles with a base such as sodium hydroxide and an acid suchas acetic acid or sulfuric acid unexpectedly increases the filtrationwater loss volume (mL) of the drilling fluid composition by 14-85%,preferably 20-80%, preferably 30-75% compared to a drilling fluidcomposition that utilizes de-oiled date pit particles but is otherwisesubstantially the same. Drilling fluids having such high filtrationwater loss volumes are particularly advantageous for underbalanceddrilling (UBD) operations.

The ability to adjust the filtration volume loss properties of thedrilling fluid compositions herein by simple selection of date pitparticle processing procedures is particularly advantageous, with basetreatment resulting in drilling fluids having decreased filtration lossproperties suitable for OBD operations, and base followed by acidtreatment resulting in drilling fluids having increased filtration lossproperties which is advantageous for UBD operations. Non-de-oiled (ND)and de-oiled (DO) date pit particles can also provide acceptabledrilling fluid, for example in terms of lost circulation materials.However, such drilling fluids containing non-de-oiled (ND) or de-oiled(DO) date pit particles are generally inferior to their treated date pitparticle counterparts, particularly in OBD and UBD applications, and thepreferred order of use in terms of drilling fluid properties isgenerally: treated date pit particles (CM)>de-oiled date pit particles(DO)>non-de-oiled date pit particles (ND).

Treated date pit particles have also been found to be superior densityreducing agents compared to non-de-oiled and de-oiled date pitparticles. For example, drilling fluid compositions that contain treateddate pit particles (i.e., either treated with a base or treated withboth a base and an acid) have a density of less than 8.6 lb/gal,preferably less than 8.5 lb/gal, more preferably less than 8.4 lb/gal,for example 6.5-8.5 lb/gal, preferably 6.7-8.4 lb/gal, preferably6.9-8.3 lb/gal, preferably 7.0-8.0 lb/gal, preferably 7.1-7.8 lb/gal.The density measurements are taken with a calibrated mud balanceaccording to the procedure in American Petroleum Institute (API)standard 13B-1 (ANSI/API 13B-1/ISO 10414-1) and reported in terms ofpounds per US gallon (lb/gal). In some embodiments, drilling fluidscontaining treated date pit particles have a density (in lb/gal) that is3-20%, preferably 4-16%, preferably 5-12% lower than a drilling fluidthat is substantially the same except for the presence of de-oiled datepit particles in lieu of the treated date pit particles. Treated datepit particles thus provide drilling fluid compositions having superiordensity control performance over de-oiled and non-de-oiled counterparts.

In some embodiments, the drilling fluid composition of the presentdisclosure contains treated date pit particles, and has a plasticviscosity of 3.0-3.5 cP, preferably 3.1-3.4 cP, preferably 3.2-3.3 cP asdetermined by a direct-indicating viscometer, such as a Fann 6-speed V-Gmeter, model 35A using a 600 rpm dial reading and a 300 rpm dial readingaccording to American Petroleum Institute (API) standard procedure 13B-1(ANSI/API 13B-1/ISO 10414-1). The plastic viscosity is determined by thefollowing equation:

Plastic viscosity(PV,cP)=600 rpm−300 rpm reading.

In some embodiments, the treated date pit particles may be furthermodified (e.g., formed into a composite with an acrylamide-basedpolymer), or functionalized (e.g., hydrogenated or partiallyhydrogenated to form fully or partially saturated treated date pitsparticles). In preferred embodiments, the date pits are not treated orfunctionalized in a manner other than being i) de-oiled and ii) treatedwith a base or both a base and an acid, as described later, whenformulated into a drilling fluid.

Aqueous Base Fluid

The drilling fluid composition also includes an aqueous base fluid. Theaqueous base fluid may refer to any water containing solution, includingsaltwater, hard water, and fresh water. Drilling muds are ordinarilyclassified as saltwater muds when they contain over 1% salt (about 6000ppm of chloride ion). Therefore, for purposes of this description, theterm “saltwater” will include aqueous base fluids with a chloride ioncontent of between about 6000 ppm and saturation, and is intended toencompass seawater and other types of saltwater including groundwatercontaining additional impurities typically found therein. The term “hardwater” will include water having mineral concentrations between about2000 mg/L and about 300,000 mg/L. The term “fresh water” includes watersources that contain less than 6000 ppm, preferably less than 5000 ppm,preferably less than 4000 ppm, preferably less than 3000 ppm, preferablyless than 2000 ppm, preferably less than 1000 ppm, preferably less than500 ppm of salts, minerals, or any other dissolved solids. Salts thatmay be present in saltwater, hard water, and/or fresh water may be, butare not limited to, cations such as sodium, magnesium, calcium,potassium, ammonium, and iron, and anions such as chloride, bicarbonate,carbonate, sulfate, sulfite, phosphate, iodide, nitrate, acetate,citrate, fluoride, and nitrite.

In some embodiments, the aqueous base fluid is present in an amount ofat least 70 wt %, preferably at least 75 wt %, preferably at least 80 wt%, preferably at least 85 wt %, preferably at least 90 wt %, for example90-95 wt %, preferably 91-94 wt %, preferably 92-93 wt %, relative to atotal weight of the drilling fluid composition.

Additive

The presence of treated date pit particles in the drilling fluidsprovides several advantages as discussed previously, such as forexample, control of fluid loss, density reduction, modification ofdrilling fluid rheological properties, and/or corrosion prevention. Whencombined in appropriate amounts with a suitable viscosifier in anaqueous base fluid, the resulting drilling fluid possess superiorcharacteristics that make it suitable for multi-purpose drillingapplications, while also being able to easily and cost effectively tunethe drilling fluid properties by selection of date pit particletreatment processing. As such, in preferred embodiments, the drillingfluid compositions herein are substantially free of one or moreadditional fluid loss additives, density reducing agents, rheologymodifying agents for modification/control of fluid loss, rheology,and/or density properties of the drilling fluid. However, in someembodiments, the drilling fluid composition includes one or more of afluid loss additive, a density reducing agent, or a rheology modifyingagent, in addition to the treated date pit particles and theviscosifier, in order to provide further control over the drilling fluidproperties.

Exemplary fluid loss additives include, but are not limited to,cellulose ethers such as ethyl cellulose and carboxymethyl cellulose,polysaccharides, polyacrylamide, polyvinyl acetate, hydroxypropyl guar,carboxymethyl guar, and carboxymethyl hydroxypropyl guar.

Exemplary density reducing agents include, but are not limited to,nitrogen gas or other gases that are injected into the drilling fluid;hollow microspheres made of glass, ceramics, polymers, etc.; andaerogels such as silica aerogels.

Exemplary rheology modifying agents include, but are not limited to,date pit particles which have not been treated (e.g., non-de-oiled datepit particles, de-oiled date pit particles, etc.); polymers formed fromwater soluble allylic monomers such as allylic quaternary ammoniumsalts; and other products derived from agricultural materials (e.g.,plants) including products derived from the husks, shells, coir, seeds,flesh, roots, leaves, leaflets, fronds, flowers, fruit, fruit clusters,empty fruit bunches, stalks, stems, and the like from said agriculturalmaterials. Specifically, other products derived from agriculturalmaterials that may act as rheology modifiers include palm-basedproducts, (e.g., palm oil products, palm shell, palm kernels, palm oilfuel ash (POFA), and oil palm shell (OPS)), grass powder or grass ashpowder, tree nut-based particles, basil seeds, cotton seeds, corn seeds,watermelon seeds, sunflower seeds, pumpkin seeds, kapok seeds, flaxseeds, cattail seeds, cherry pits, wood, nut shell particles, seed shellparticles, psyllium seed husks, modified starch, and the like.

In some embodiments, the drilling fluid composition optionally includesat least one additive selected from the group consisting of anantiscalant, a thickener, a deflocculant, a lubricant, a buffer, abiocide, and a weighting agent. In preferred embodiments, no additiveother than the treated date pit particles and the viscosifier, ispresent in the drilling fluid compositions. When present, a total weightof the at least one additive in the drilling fluid composition is up to10 wt %, preferably up to 9 wt %, preferably up to 8 wt %, preferably upto 7 wt %, preferably up to 6 wt %, preferably up to 5 wt %, preferablyup to 4 wt %, preferably up to 3 wt %, preferably up to 2 wt %,preferably up to 1 wt %, preferably up to 0.5 wt %, preferably up to 0.1wt %, preferably up to 0.01 wt %, relative to the total weight of thedrilling fluid composition.

In some embodiments, an antiscalant is incorporated as a part of thedrilling fluid composition. The term “antiscalant” refers to anychemical agent that prevents, slows, minimizes, or stops theprecipitation of scale (e.g. calcium carbonate, calcium sulfate, bariumsulfate, strontium sulfate, calcium phosphate, calcium fluoride, calciumsilicate, magnesium hydroxide, zinc carbonate, and the like) in thewellbore. For example, in the case of carbonate scale, antiscalantscause the disassociation of the carbonate to produce the oxide andcarbon dioxide. Antiscalants which may be used in the present disclosureinclude inorganic phosphates (e.g., sodium hexametaphosphate, sodiumtripolyphosphate, etc.), phosphonic acids (e.g., hydroxyethylidenediphosphonic acid, aminotris(methylenephosphonic acid) (ATMP)), organicmonocarboxylic acids (e.g., lactic, acetic, acrylic, formic, glucuronic,stearic, gallic, palmitic, caffeic, glyoxylic, malic, and salicylicacid), polycarboxylic acids (e.g., butane-tricarboxylic acid, maleicacid, itaconic, fumaric, citric, oxalic, adipic, humic, sebacic, fulvic,and tartaric acid), phosphonates, sulfonic acids (e.g., vinyl sulfonicacid, allyl sulfonic acid, etc.), polycarboxylic acid polymers (e.g.,polymers containing 3-allyloxy-2-hydroxy-propionic acid monomers),sulfonated polymers (e.g., vinyl monomers having a sulfonic acid group),and the like and mixtures thereof.

In some embodiments, a thickener is present in the drilling fluidcomposition. Exemplary thickeners include guar gum, glycol, polyanioniccellulose (PAC), starch, alginic acid (E400), sodium alginate (E401),potassium alginate (E402), ammonium alginate (E403), calcium alginate(E404), agar (E406), carrageenan (E407), locust bean gum (E410), pectin(E440), and Gelatin (E441) and mixtures thereof.

A deflocculant may also be incorporated into the drilling fluidcomposition. A deflocculant is a chemical additive used to prevent acolloid from coming out of suspension or to thin suspensions orslurries. One type of deflocculant is an anionic polyelectrolyte, suchas acrylates (e.g., low molecular weight polyacrylic acids, ethylacrylate-based polymers), polyphosphates, pyrophosphates (e.g., sodiumacid pyrophosphate (SAPP)), polysulfates (e.g., sulfoethyl and/orsulfophenyl acrylamide-based polymers) lignosulfonates (Lig) or tannicacid derivates such as Quebracho.

The drilling fluid composition may also include a lubricant, such as anoil, for lubrication. The lubricant may be a synthetic oil or abiolubricant, such as those derived from plants and animals for examplevegetable oils. Synthetic oils include, but are not limited to,polyalpha-olefin (PAO), synthetic esters, polyalkylene glycols (PAG),phosphate esters, alkylated naphthalenes (AN), silicate esters, ionicfluids, multiply alkylated cyclopentanes (MAC). Exemplary vegetableoil-based lubricants (i.e. biolubricants) that may be used in thepresent disclosure include canola oil, castor oil, palm oil, sunflowerseed oil and rapeseed oil from vegetable sources, and Tall oil from treesources, and the like.

The drilling fluid compositions of the present disclosure may also beformulated to include a buffer for adjusting/controlling the pH of thedrilling fluid and/or fluid located within the wellbore. Exemplarybuffers include, but are not limited to, monosodium phosphate, disodiumphosphate, sodium tripolyphosphate, and the like.

A biocide may also be present in the drilling fluid formulations to killor prevent bacteria from growing in the drilling fluid and/or within thegeological formation. Exemplary biocides include, but are not limitedto, phenoxyethanol, ethylhexyl glycerine, benzyl alcohol, methylchloroisothiazolinone, methyl isothiazolinone, methyl paraben, ethylparaben, propylene glycol, bronopol, benzoic acid, imidazolinidyl urea,a 2,2-dibromo-3-nitrilopropionamide, and 2-bromo-2-nitro-1,3-propanediol.

The drilling fluid composition may also include a weighting agentwithout adversely affecting its stability or other properties in orderto maintain sufficient bottom hole pressure in the wellbore to preventan influx of formation fluids. Exemplary weighting agents includecalcium carbonate (chalk), barite, sodium sulfate, hematite, siderite,ilmenite, and combinations thereof.

Method of Making the Drilling Fluid

According to a second aspect, the present disclosure relates to a methodof making the drilling fluid composition. Initially, date pits may beobtained, for example, the date pits may be produced as a wasteby-product from date processing, and the date pits may be obtained fromdate processing plants to provide a sustainable source of the date pits.Moreover, local sources of date pits may reduce the cost of importeddate pit products. In some embodiments, the date pits may be obtainedfrom the species phoenix daclylifera. It should be appreciated that, insome embodiments, the date pits may be obtained from geneticallymodified date palms (that is, genetically modified organisms (GMOs)).

The obtained date pits are preferably subject to further processingshortly after they are obtained to minimize degradative decompositiondue to natural enzymatic reactions as well as growth of bacteria. Toprocess, the obtained date pits may be optionally soaked or washed withwater, preferably soaked and/or sonicated in water to release anyadhering dirt and/or date flesh. For example, the obtained date pits maybe soaked and/or sonicated in water for at least about 5, at least about10 minutes, at least about 30 minutes, at least about an hour, and up toabout 48 hours, up to about 24 hours, up to about 10 hours, up to about5 hours. In some embodiments, the date pits may be dried using a sundrying process over a 1-12 hour, 2-10 hour, or 3-8 hour time period, oralternatively, they may be dried in an oven at 150-300° C., 175-280° C.,or 200-260° C. to provide an acceptable moisture content as describedpreviously (e.g., 0.01-5 wt % moisture content).

Next, the date pits may be ground to an appropriate particle size (e.g.,less than 200 μm) and roundness (e.g., sub-angular) as describedpreviously using a suitable grinder (e.g., an industrial grinder) toform dried date pit particles (also referred to as non-de-oiled date pitparticles (ND)). In some embodiments, the date pits may be crushedbefore being ground. For example, in such embodiments, the date pits maybe crushed to a first size, and the crushed date pits may be ground to asecond size smaller than the first size. The non-de-oiled date pitparticles may be optionally sifted using one or a plurality of sieveswith varying sieve openings for selection of a desired particle size.For example, the non-de-oiled date pit particles may be filtered using aseries of sieves with decreasing sieve size openings until a desiredparticle size is obtained.

The non-de-oiled date pit particles may then be de-oiled by contactingwith an organic solvent to remove oils and form the de-oiled date pitparticles. Exemplary organic solvents which can be used to de-oil thedried date pit particles include, but are not limited to, ethers (e.g.diethyl ether, tetrahydrofuran, 1,4-dioxane, tetrahydropyran, t-butylmethyl ether, cyclopentyl methyl ether, di-isopropyl ether), glycolethers (e.g. 1,2-dimethoxyethane, diglyme), alcohols (e.g. methanol,ethanol, trifluoroethanol, n-propanol, i-propanol, n-butanol, i-butanol,t-butanol, n-pentanol, i-pentanol, 2-methyl-2-butanol), aromaticsolvents (e.g. benzene, o-xylene, m-xylene, p-xylene, and mixtures ofxylenes, toluene, mesitylene, anisole, 1,2-dimethoxybenzene),chlorinated solvents (e.g. chlorobenzene, dichloromethane,1,2-dichloroethane, 1,1-dichloroethane, chloroform, carbontetrachloride), ester solvents (e.g. ethyl acetate (EtOAc), propylacetate), ketones (e.g. acetone, butanone), alkane solvents (e.g.pentane, cyclopentane, hexanes, cyclohexane, heptanes, cycloheptane,octanes), acetonitrile, and mixtures of one or more of these organicsolvents. In preferred embodiments, the organic solvent is an alkanesolvent or an alcohol solvent, preferably the organic solvent is atleast one selected from the group consisting of pentane, hexane,methanol, and ethanol. Most preferably the organic solvent is hexane.

Any amount of organic solvent can be used for the de-oiling procedure solong as an acceptable amount of fat content (e.g., fatty material suchas fatty esters, fatty hydrocarbon oils) is removed to provide thede-oiled date pit particles as discussed heretofore. A typical volumeratio of the organic solvent to the non-de-oiled date pit particles usedfor the de-oiling procedure ranges from 2:1 to 50:1, or 3:1 to 40:1, or5:1 to 30:1, or 8:1 to 20:1, or 10:1 to 15:1. The de-oiling proceduremay be performed by methods known to those of ordinary skill in the art.For example, the dried date pit particles may be immobilized onto afilter or inside a cartridge filter and the organic solvent (which mayoptionally be at elevated temperature) may be passed through.Alternatively, the dried date pit particles may be mixed with theorganic solvent in a vessel with optional heating and/or stirring andthen filtered to recover the de-oiled date pit particles. In preferredembodiments, the dried date pit particles are extracted with the organicsolvent using a continuous extraction process in an extractionapparatus, for example, a Soxhlet extractor or a Kumagawa extractor atthe boiling temperature of the organic solvent employed. For example,the fat content of non-de-oiled date pit particles may be reduced toacceptable levels described previously by refluxing hexane (boilingpoint of 68.5-69.1° C. at standard pressure) in a Soxhlet extractor, orother continuous extractor apparatus, containing the non-de-oiled datepit particles, thereby forming de-oiled date pit particles.

To form the treated date pit particles, the de-oiled date pit particlesare mixed with a base and water to form an alkaline mixture, and thealkaline mixture is optionally agitated, for example in a shaker, for upto an hour, or up to 45 minutes, or up to 30 minutes, or up to 15minutes or until the base has completely dissolved. Typically, aconcentration of the base in water ranges from 0.5-6 M, preferably 1-5M, preferably 1.5-4 M, preferably 2-3 M. In some embodiments, a weightratio of the base to the de-oiled date pit particles ranges from 5:1 to1:3, preferably 4:1 to 1:2, preferably 3:1 to 1:1.5, preferably 2:1 to1:1.2. In some embodiments, a pH of the alkaline solution is 9-15,preferably 10-14.5, preferably 11-14, preferably 12-13.5. Bases that aresuitable for treating the de-oiled date pit particles include hydroxidebases such as an alkali metal hydroxide, an alkali earth metalhydroxide, and/or an ammonium hydroxide. For example, the base may beone or more of lithium hydroxide, sodium hydroxide, potassium hydroxide,rubidium hydroxide, cesium hydroxide, magnesium hydroxide, calciumhydroxide, strontium hydroxide, barium hydroxide, and/or a hydroxidesalt of an ammonium cation (e.g., protonated forms of ammonia,methylamine, dimethylamine, trimethylamine, ethylamine, diethylamine,triethylamine, diisopropylethylamine, piperidine, N-methylpiperidine,2,2,6,6-tetramethylpiperidine, morpholine, N-methylmorpholine,monoethanolamine, diethanolamine, triethanolamine, and the like). Inpreferred embodiments, the base is sodium hydroxide.

After forming the alkaline mixture, the alkaline mixture is nextsubjected to a freeze/thaw process to form a freeze/thaw mixturecomprising the treated date pit particles in water. In one example, thefreeze thaw process may involve:

1) subjecting the alkaline mixture to a temperature of 0° C. or below,preferably −10° C. or below, preferably −20° C. or below, preferably−30° C. or below, preferably −40° C. or below for at least 1 hour, atleast 2 hours, at least 3 hours, at least 4 hours, at least 5 hours, atleast 6 hours, or any other conditions suitable for freezing thealkaline mixture to form a frozen mixture;

2) thawing the frozen mixture at a temperature of 20-50° C., preferably21-45° C., preferably 22-40° C., preferably 23-35° C. using standardatmospheric conditions or under applied heat such as a heating bath(e.g., heated water bath) or using heating circulators to thaw thefrozen mixture and form a freeze/thaw mixture in liquid state. The timeperiod for the thawing is dependent on the operation scale and thetemperature conditions employed, but typically ranges from 30 minutes to4 hours, or 1-3 hours; and

3) optionally agitating the freeze/thaw mixture for at least 15 minutes,at least 30 minutes, at least 45 minutes, at least 1 hour, and up to 3hours, optionally under continued heating, to ensure melting of allfrozen clumps and complete reformation to a liquid state. Thefreeze/thaw mixture can be agitated by shaking in a shaker apparatus,stirring using a mechanical stirrer or magnetic stirrer, or by flowingforces such as by pumping the freeze/thaw mixture through a circulatorpump.

In some embodiments, the date pit particles which have been treated witha base as described above are taken on and formulated into a drillingfluid composition. In other embodiments, the date pit particles whichhave been treated with a base as described above are next treated withan acid by adding an acid to the freeze/thaw mixture produced afterthawing or after/during the optional agitating step. In embodimentswhere it is desirable to formulate drilling fluid compositions having arelatively high filtration water loss volume (mL) and relatively lowdensity, for example for use in underbalanced drilling (UBD) operations,the acid treatment step is preferably employed. It is clear thattreating date pit particles with an acid has an influence of theresulting drilling fluid properties, in particular filtration fluidloss, compared to date pit particle treatment with base alone in afreeze/thaw process, as discussed throughout this disclosure. Thisdifference may be attributed to modification of the drilling fluid pH,or it may be attributed to a chemical modification of the treated datepit particles themselves, with acid treatment resulting in partialdegradation or modification of the date pit particle structure.

When the date pit particles are treated with both a base and an acid,enough acid is preferably added to the freeze/thaw mixture toneutralize/acidify the pH to a value of 2-8, preferably 3-7, preferably4-6. In some embodiments, a molar ratio of the acid to the base employedduring the treatment process ranges from 8:1 to 1:1, preferably 6:1 to1.5:1, preferably 4:1 to 2:1, preferably 3:1 to 2.5:1. The acid employedmay be an inorganic acid or an organic acid. Exemplary inorganic acidswhich can be used to treat the date pit particles include, but are notlimited to, hydrochloric acid, nitric acid, phosphoric acid, sulfuricacid, hydrobromic acid, perchloric acid, and hydroiodic acid. Organicacids which can be used herein include alkanoic acids having 1 to 8carbon atoms, hydroxycarboxylic acids having 2 to 10 carbon atoms,dicarboxylic acids having 2 to 10 carbon atoms, tricarboxylic acidshaving 4 to 10 carbon atoms, organosulfonic acids, and organophosphonicacids. Suitable organic acids include acetic acid, formic acid,propionic acid, butyric acid, pentanoic acid, hexanoic acid, oxalicacid, malonic acid, lactic acid, glyceric acid, glycolic acid, malicacid, citric acid, benzoic acid, p-toluenesulfonic acid,trifluoromethanesulfonic acid, and the like, as well as mixturesthereof. Preferred organic acids have a solubility in water of at least50% by volume. In preferred embodiments, the acid used to treat the datepit particles is acetic acid or sulfuric acid. The acid may be added asan aqueous solution or neat (e.g., glacial form when acetic acid isemployed, or concentrated/fuming form when sulfuric acid is employed).

After treating the de-oiled date pit particles with a base or both abase and an acid as described above to form a freeze/thaw mixture thatcontains the treated date pit particles in water, an appropriate amountof the freeze/thaw mixture is then combined with the viscosifier, theaqueous base fluid, and any optional additive, to form the drillingfluid compositions herein. Thorough mixing may be performed to avoidcreating lumps or “fish eyes,” for example, by stirring the resultingdrilling fluid composition with a stirring speed of 1-800 rpm, or 2-700rpm, or 3-600 rpm. In some embodiments, when the viscosifier isbentonite, the various ingredients of the drilling fluid composition aremixed for a sufficient period of time to allow for hydration of thebentonite clay in the aqueous base fluid, and this period of time isusually between about 5 and about 60 minutes, preferably between about10 and about 40 minutes, preferably between about 20 and about 30minutes. Other mixing times may be also utilized to make the drillingmud composition (e.g. less than 5 minutes, or more than 60 minutes) solong as the drilling fluid composition is substantially free of lumps.

In some embodiments, the pH of the drilling fluid composition may beadjusted depending on the drilling application or problems that may beencountered during a drilling operation. For example, the pH of thedrilling fluid composition may be adjusted so as to provide forincreased solubility of the various organic components in the fluidcomposition such as organic components from the date pit particles(e.g., treated date pit particles) or one or more additives (e.g., theantiscalant, the thickener, etc.), for preventing acid promoteddamage/corrosion to drilling equipment, for minimizing scale formation,etc. In some embodiments, the pH of the drilling fluid is preferablybetween about 8 and 12, preferably 9 and 11. In some embodiments, the pHof the drilling fluid composition is between about 1 and 8, preferably 2and 7, more preferably 3 and 6. The pH may be adjusted using one or moreof the aforementioned acids or bases, or buffers known to those ofordinary skill in the art (e.g. monosodium phosphate, disodiumphosphate, sodium tripolyphosphate, etc.).

Process for Drilling a Subterranean Geological Formation

According to a third aspect, the present disclosure relates to a processfor drilling a subterranean geological formation, involving drilling thesubterranean geological formation with a drill bit to form a wellbore,and injecting the drilling fluid composition into the subterraneangeological formation through the wellbore.

The drilling fluids of the present disclosure are multi-purpose and canbe used for a variety of drilling operations in a variety of types ofwells. For example, the drilling fluids disclosed herein may be injectedinto new wells, wells with good or poor production, vertical wells,slanted wells, horizontally drilled wells, and more. The “wellbore” asused herein may be drilled into any geological structure or formationthat may contain various combinations of natural gas (i.e., primarilymethane), light hydrocarbon or non-hydrocarbon gases (includingcondensable and non-condensable gases), light hydrocarbon liquids, heavyhydrocarbon liquids, crude oil, rock, oil shale, bitumen, oil sands,tar, coal, and water. Exemplary non-condensable gases include hydrogen,carbon monoxide, carbon dioxide, methane, and other light hydrocarbons.

In some embodiments, the method further comprises circulating thedrilling fluid composition within the wellbore after the injecting, forexample, for at least 30 minutes, at least 45 minutes, at least an hour,and up to 5 hours, or up to 3 hours.

In some embodiments, the drilling fluid composition includes at leastone additive selected from the group consisting of an antiscalant, athickener, a deflocculant, a lubricant, a buffer, a biocide, and aweighting agent. In an alternative embodiment, the at least oneadditive, when employed, may be injected into the geological formationas a separate component from the drilling fluid composition.

In some embodiments, the drilling fluids may by employed in overbalanceddrilling operations. In conventional or “overbalanced” drilling (OBD),drilling fluid is pumped into the well shaft at pressure higher than inthe reservoir. This keeps the oil and gas, for example, in the reservoirduring drilling. The pressures in the wellbore during drilling anddrilling fluid injection can vary widely depending on the depth of thewell, the type of reservoir, and many other factors. In someembodiments, the drilling fluid is injected at a pressure sufficient tomaintain a positive pressure differential within the wellbore (i.e.,drilling fluid pressure minus formation pressure) of at least 10 psi, atleast 20 psi, at least 30 psi, at least 40 psi, at least 50 psi, atleast 100 psi, at least 300 psi, at least 500 psi, at least 1,000 psi,and up to 3,000 psi, up to 2,500 psi, or up to 2,000 psi, or up to 1,500psi across all depths of the wellbore (e.g., depths from 5,000-14,000feet). The pressure within the wellbore can be measured and adjustedusing techniques known to those of ordinary skill in the art, forexample techniques disclosed in U.S. Pat. No. 9,725,974B2, U.S. Pat. No.9,328,573 B2 and U.S. Pat. No. 6,367,566B1, each incorporated herein byreference in its entirety.

To achieve acceptable pressures, the drilling fluid is circulated andremains in the wellbore (down the drill pipe and back up the annulus) inorder to control and prevent caving of the wellbore. However, due to thepressures in the wellbore, fluid loss is a common occurrence in thesedrilling operations. In some situations when the borehole penetrates afracture in the formation through which most of the drilling fluid maybe lost, the rate of loss may exceed the rate of replacement. Drillingoperations may have to be stopped until this zone is sealed and fluidloss to the fracture is reduced to an acceptable level. This phenomenonof losing the drilling fluid to the formation is referred to as lostcirculation. In overbalanced drilling, loss of drilling fluid to theformation is undesirable as it (1) leads to poor circulation andtherefore less efficient removal of cuttings, (2) requires additionalcost in rig time, manpower and material to replenish the lost mud andrestore circulation and in extreme cases, (3) leads to insufficientdownhole hydrostatic pressure which may lead to a blowout.

In attempts to compensate for fluid loss, drilling fluids used inoverbalanced drilling are designed to form a thin, low permeabilityfilter cake (mud cake) over time that seals openings in formations toreduce the unwanted influx of fluids into permeable formations. A mudcake forms when the drilling fluid contains particles that areapproximately the same size as or have diameters greater than about onethird of the pore diameter (or the width of any opening such as inducedfractures) in the formation being drilled. Even with the formation of amud cake, fluid loss may still be an issue and fluid loss controladditives are used. Therefore, when the process herein involvesoverbalanced drilling (i.e. where the drilling fluid composition isinjected into the subterranean geological formation through the wellboreto maintain a pressure in the wellbore that is higher than a staticpressure of the subterranean geological formation), drilling fluidscontaining the treated date pit particles which are ii) treated with abase are preferably utilized herein, since these drilling fluids possessadvantageous filtration water loss properties and advantageous densityproperties as discussed previously, which makes them well-suited forthese types of drilling processes.

In some embodiments, the drilling fluids may be employed inunderbalanced drilling (UBD) operations where the pressure in thewellbore is kept lower than the static fluid pressure in the formationbeing drilled. As the well is being drilled, formation fluid flows intothe wellbore and up to the surface. In some embodiments, the drillingfluid is injected at a pressure sufficient to maintain a negativepressure differential within the wellbore (i.e., drilling fluid pressureminus formation pressure) of from −10 psi, from −20 psi, from −30 psi,from −40 psi, from −50 psi, from −100 psi, from −300 psi, from −500 psi,from −1,000 psi, and up to −3,000 psi, up to −2,500 psi, or up to −2,000psi, or up to −1,500 psi across all depths of the wellbore (e.g., depthsfrom 5,000-14,000 feet). The pressure within the wellbore can bemeasured and adjusted using techniques known to those of ordinary skillin the art, for example techniques disclosed in U.S. Pat. No.9,725,974B2, U.S. Pat. No. 9,328,573 B2 and U.S. Pat. No. 6,367,566B1,each incorporated herein by reference in its entirety.

This type of drilling process may employ a “rotating head” at thesurface, which acts as a seal that diverts produced fluids to aseparator while allowing the drill string to continue rotating.Separating produced fluids at the surface can be costly, and thuslow-cost drilling fluids are often employed to help offset theseexpenses. Production often commences earlier in UBD than in OBD, andthus it is advantageous to use drilling fluids which form a more porousfilter cake with a higher filtrate volume. Therefore, when the processinvolves underbalanced drilling (i.e. where the drilling fluidcomposition is injected into the subterranean geological formationthrough the wellbore to maintain a pressure in the wellbore that islower than a static pressure of the subterranean geological formation),drilling fluids containing the treated date pit particles which are ii)treated with a base and an acid are preferably utilized herein, sincethese drilling fluids possess increased filtration water loss propertiesand advantageous density properties, which makes them well-suited forUBD processes.

Alternatively, the drilling fluid compositions may be utilized inbalanced differential pressure drilling operations, whereby the drillingfluids herein are injected into the wellbore at pressures sufficient tomatch the formation pressure (i.e., the drilling fluid pressure isapproximately equal to the formation pressure).

In some embodiments, the drilling fluid compositions herein may beutilized for fracking processes. “Fracking” or “fracturing” as usedherein refers to the process of initiating and subsequently propagatinga fracture of the rock layer by employing the pressure of a fluid as thesource of energy. In some embodiments, fracking is accomplished bypumping in liquids at high pressure. A hydraulic fracture may be formedby pumping a fracturing fluid (i.e. the drilling fluid composition, inone or more of its embodiments) into the wellbore at a rate sufficientto increase the pressure downhole to a value in excess of a criticalfracture pressure associated with the formation rock. The pressurecauses the formation to crack, allowing the fracturing fluid to enterand extend the crack farther into the formation. Following fracking byhigh pressures, the fractured formation allows more hydrocarbons (e.g.,methane, condensate, ethane, oil) and/or water to be extracted since theformation walls are more porous. In some embodiments, the drilling fluidcomposition is injected into the subterranean geological formationthrough a wellbore at a pressure of at least 5,000 psi, at least 5,500psi, at least 6,000 psi, at least 6,500 psi, at least 7,000 psi, atleast 7,500 psi to fracture the underground geological formation andform fissures in the underground geological formation.

The process may further include injecting a proppant into the wellboreto maintain the structural integrity of the wellbore. A “proppant” isused herein to refer to any granular material that, in an aqueousmixture, can be used to fracture the rock formation and to providestructural support to the wellbore and/or fissures that develop in therock formation due to pressurizing the rock formation during fracking.In some embodiments, the proppant is one or more of grains of sand,ceramic, silica, quartz, or other particulates that prevent thefractures from closing when the injection is stopped.

In some embodiments, the drilling fluid compositions herein may beuseful completion fluids. Completion of a well refers to the operationsperformed during the period from drilling in the pay zone until the timethe well is put into production. These operations may include additionaldrilling, placement of downhole hardware, perforation, sand controloperations, such as gravel packing, and cleaning out downhole debris. Acompletion fluid is often defined as a wellbore fluid used to facilitatesuch operations. The completion fluid's primary function is to controlthe pressure of the formation fluid by virtue of its specific gravity.The type of operation performed, the bottom hole conditions, and thenature of the formation will dictate other properties, such asviscosity. The drilling fluids of the present disclosure may thus beused in drilling completion processes, for example, to assist incleaning out the drilled borehole, further drilling operations, to placedownhole hardware, and to control and maintain a desired downholepressure.

The examples below are intended to further illustrate protocols forpreparing and characterizing the treated date pit particles and thedrilling fluid compositions, and are not intended to limit the scope ofthe claims.

EXAMPLES Materials

Commercial bentonite (Alumino Silicate Hydrate Montmorillonite) was usedas the base material for preparing the water-based drilling formulation.Date pit used in this study was collected from date from a household inEastern Province of Saudi Arabia. NaOH (Merck) and distilled water wereused as the solvent for the experiments.

Date Pit Processing

The Date seed were soaked in water, washed by sonication to free themfrom any adhering date flesh and then dried. Drying can be done underthe sun or in an oven. The dried seeds were ground to a powder andde-oiled using hexane in a Soxhlet apparatus. Other solvents such aspentane, ethanol or methanol can also be used.

Preparation of Modified Date Pit—Based Drilling Fluid Additive

A predetermined amount of solvent was prepared as mixed solution of 2.5g of NaOH in 29 mL of H₂O. A desired amount of the de-oiled date pitpowder was immersed into the solvent and agitated for 30 minutes using aMulti-Wrist shaker. There will be a slight increase in temperature.Thus, the container needs to be first slightly agitated manually. Inaddition, it should be opened intermittently to discharge theaccumulated pressure above the solution. This should be done until acomplete dissolution of NaOH pellets is observed.

The mixture was placed in the deep freezer for 4 hours at −20° C. tofreeze. The frozen mixture was removed and then defrosted. Defrostingcan be under atmospheric conditions or in water. Once completelydefrosted, the mixture was shaken for at least 30 minutes. Using thisprocedure, various concentrations of formulation were prepared.Compositions of these formulations are contained in Table 2.

TABLE 2 The composition of the date pit-based polymeric additive WaterDate Pit NaOH Sample # Sample name (g) (g) (g) 1 PB 0.0 0.00 0.0 2 NaPB26.9 0.00 2.5 3 1.50DP 26.9 1.50 2.5 4 3.00DP 26.9 3.00 2.5 PB:Formulation containing only Pure Bentonite (no additive included); NaPB:formulation containing Pure Bentonite and NaOH (The only additive isNaOH).

Evaluation of the Date Pit—Based Drilling Fluid Additive

The ensuing formulations prepared using the date pit powder wereevaluated by measuring their properties at specific temperature.

Drilling Fluid Formulation

Date pit particles/bentonite drilling fluid formulation was prepared bymixing 20.0 g mixture of bentonite and date particles with water.

Density Measurement

A calibrated mud balance with accuracy of 0.1 lb/gal was used as thedensity-measuring device for the drilling fluids. The procedure followedis based on the API procedures for density measurement. Drilling fluidis poured into the fluid holding cup and covered with the screw-on lidand then balanced by a fixed counterweight at the other end. Densityreading is taken when the level-bubble on the beam is accuratelybalanced.

Rheological Properties of Drilling Fluids

The viscometer was used to determine the rheological properties as perAPI procedures.

Filtration Properties/Fluid Loss Control Measurement

Filtration experiments were carried out on drilling fluids at laboratoryconditions to determine the filtration loss volume and cake thickness.The filter press was used with nitrogen gas providing the necessarypressure. Drilling fluid was stirred and poured into the cell fittedwith filter paper underneath. The assembly was mounted on the filterpress and graduated cylinder was placed under drain tube to receivefiltrate. 100 psi pressure was applied and test period was started atthe same time. The filtrate volume was recorded for 30 min.

Drilling Fluid Formulation Performance with and without Additive

The results displayed in Table 3 shows the potential of the formulationin controlling the density, and the fluid loss. There is a continuousincrease in the performance of the formulation with an increase in theamount of chemically modified date pit that was dispersed within thematrix. The density reduced by about 14% with the addition of 3 g of themodified sample as compared to the formulation containing only the purebentonite. The plastic viscosity also increases with increase in thequantity of additive dispersed into the formulation. In a similarmanner, the filtration properties were observed to increase with anincrease in the amount of additive. For example, the fluid loss controlproperties increased by 35% and 54% in terms of filtrate volume and cakethickness, respectively, as compared with the pure bentoniteformulation.

TABLE 3 Performance of Drilling Fluid Formulation Plastic Volume ofresidue Density Viscosity water after 30 thickness Sample # (lb/gal)(cP) mins (mL) (in) 1 8.60 4.305 26.80 0.1085 2 8.60 3.327 20.20 0.04993 7.70 3.131 18.20 0.0485 4 7.43 3.327 17.40 0.0498

Chemical Comparison of Non-De-Oiled, De-Oiled, and Treated Date PitParticles

Date pit is a multicomponent naturally occurring polymer. Most of thecomponents of date pit are not soluble in water. However, water-baseddrilling fluid formulation is better improved by adding materials thatare water soluble. Thus some initial pretreatment and further chemicalmodifications are needed to enhance performance properties of date pitand improve its purity. The original date pit is different from thechemically modified version as disclosed herein. FTIR analysis wasperformed on three different date samples based on the differenttreatment stages:

i. Non-Deoiled (ND): Date pit particles before pretreatment usingorganic solvent

ii. Deoiled (DO): Date pit particles obtained after the organic solventtreatment

iii. Chemically Modified (CM): Date pit particles produced from thefreeze/thaw process.

FIG. 1 showed the FTIR spectrum of various samples before and aftertreatment. The FIGURE revealed that the chemically modified date pit isdifferent from the initial pit. It was observed that some of the datepit components (such esters, lipids, etc) were removed by the organicsolvent treatment. The removal of these components is needed to improvethe processability of the date pit. By comparing the spectrum of DO andCM, it was also observed that some of the components of DO samples havebeen modified due to the disappearance as well as shifting of some peaksof DO when compared to CM.

In terms of performance, the chemically modified particle is better as adensity reducing agent. It is also better with respect to fluid losscontrol property than the unmodified particle. See Table 5 forcomparison of the performance of DO (Example 3) and CM (Example 4).

Examples 1-4

Varieties of formulations were prepared as examples to demonstrate thepotential of the additive for application in both the overbalance andthe underbalance drilling operations. Table 4 and 5 contain thecomposition of four formulations with the NaOH modified and non-modified(DO) date pit additives. The results from these tables revealed adecrease in both the density and the filtrate volume. The observeddecrease is more pronounced for the modified samples than thenon-modified ones. For instance in Table 5, for drilling fluidformulations containing 5 mL each of the modified (CM) (Example 4) andnon-modified (DO) (Example 3) additive, the density of Example 4additive is 9% lower than that of Example 3. Similarly, the filtratevolume of Example 4 is 21% less when compared with that of Example 3(the formulation containing the non-modified (DO) date pit particles).

TABLE 4 Examples 1 and 2 Ben- Additive (mL) Filtrate Sample tonite WaterNon- NaOH Density Volume Name (g) (mL) Modified Modified (lb/gal) (mL)Example 1 20.0 350 2.00 — 8.62 29.6 Example 2 20.0 350 — 2.00 8.35 27.8

TABLE 5 Examples 3 and 4 Ben- Additive (mL) Filtrate Sample tonite WaterNon- NaOH Density Volume Name (g) (mL) Modified Modified (lb/gal) (mL)Example 3 20.0 350 5.00 — 8.60 28.1 Example 4 20.0 350 — 5.00 7.80 22.2

Examples 5-7

For UBD where the pore pressure should be higher than the mud pressure,the formation fluid is allowed to flow into the wellbore. For thisreason, production often commences earlier in UBD than OBD.Consequently, the filter cake should be more porous with higher filtratevolume. The addition of few drops of acid neutralizes the pH of thesolution and also increases the filtrate volume as shown on Tables 6, 7and 8. Two types of acid: weak (acetic acid) and strong (sulfuric) acidwere used. The results in these tables show that the addition of theseacids increased the potential of the new additives in application forunderbalance drilling. As shown in Table 6, using 2 mL of this aceticacid modified additive gave rise to 15% increase in filtrate volume and7% decrease in the density (compared to non-modified (DO) additive)which is an indication of better performance in underbalance drilling.On a similar note, using 10 mL of H₂SO₄ modified additive led to abetter underbalance drilling fluid by 83% increase and 9% decrease interms of filtrate volume and density, respectively.

TABLE 6 Example 5 Ben- Additive (mL) Filtrate Sample tonite Water Non-NaOH/Acid Density Volume Name (g) (mL) Modified Modified (lb/gal) (mL)Example 1 20.0 350 2.00 — 8.62 29.6 Example 5 20.0 350 — 2.00 ^(A) 8.0034.00 ^(A) Acetic Acid

TABLE 7 Example 6 Ben- Additive (mL) Filtrate Sample tonite Water Non-NaOH/Acid Density Volume Name (g) (mL) Modified Modified (lb/gal) (mL)Example 3 20.0 350 5.00 — 8.60 28.1 Example 6 20.0 350 — 5.00 ^(A) 7.1035.20 ^(A) Acetic Acid

TABLE 8 Example 7 Ben- Additive (mL) Filtrate Sample tonite Water NaOHNaOH/Acid Density Volume Name (g) (mL) Modified Modified (lb/gal) (mL)1.50DP 20.0 350 10.00 — 7.70 18.0 Example 7 20.0 350 — 10.00 ^(H) 7.0033.00 ^(H) H₂SO₄

In all cases, the trends of the results revealed a continuousimprovement beyond the experimental measurement conditions. Clearly,these results show that chemical modification of date pit particles cansuccessfully be used to produce a multifunctional date-pit baseddrilling fluid additive that could serve as density reducing and fluidloss control agents during drilling operations.

Example 8

The drilling fluid was prepared by mixing 20.0 g of bentonite and datepit particles. Table 9 contains the weight percent of each component ofthe drilling fluid formulation.

TABLE 9 Percent weight composition of drilling fluid formulation WaterBentonite DP Additive Sample Name (% wt) (% wt) (% wt) PB 94.59 5.410.00 *NaPB 92.11 5.26 — 1.50DP 92.11 5.26 2.63 Example 1, 2&5 94.09 5.380.54 Example 3, 4&6 93.33 5.33 1.33 Example 7 92.11 5.26 2.63 3.00DP92.11 5.26 2.63 ‘PB’ stands for ‘Pure Bentonite’. This indicates thatthe drilling fluid sample made from this PB additive contains only purebentonite, with no date pit and NaOH added. That is, no additive wasadded in this case. Similarly, ‘NaPB’ stands for ‘NaOH and PureBentonite’, indicating that its corresponding drilling fluid containsNaOH in addition to Pure Bentonite. *The % wt balance of 2.63 is thepercentage of NaOH added to this sample in order to use it as a controlto ensure that the change observed was actually coming from modifiedDate Pit particles but not from NaOH.

1: A drilling fluid composition, comprising: a viscosifier; treated datepit particles, which are i) de-oiled and ii) treated with a base or botha base and an acid; and an aqueous base fluid; wherein the treated datepit particles are present in an amount of 0.01-5 wt %, relative to atotal weight of the drilling fluid composition. 2: The drilling fluidcomposition of claim 1, wherein the viscosifier is bentonite. 3: Thedrilling fluid composition of claim 1, wherein the viscosifier ispresent in an amount of 1-10 wt %, relative to a total weight of thedrilling fluid composition. 4: The drilling fluid composition of claim1, wherein the treated date pit particles are ii) treated with a base.5: The drilling fluid composition of claim 4, wherein the base is sodiumhydroxide. 6: The drilling fluid composition of claim 4, which has afiltration water loss volume of 15-28 mL after 30 min under a pressureof 100 psi. 7: The drilling fluid composition of claim 1, wherein thetreated date pit particles are ii) treated with both a base and an acid.8: The drilling fluid composition of claim 7, wherein the base is sodiumhydroxide and the acid is acetic acid or sulfuric acid. 9: The drillingfluid composition of claim 7, which has a filtration water loss volumeof 30-40 mL after 30 min under a pressure of 100 psi. 10: The drillingfluid composition of claim 1, which has a density of 6.5-8.5 lb/gal. 11:The drilling fluid composition of claim 1, which has a plastic viscosityof 3.0-3.5 cP. 12: The drilling fluid composition of claim 1, furthercomprising at least one additive selected from the group consisting ofan antiscalant, a thickener, a deflocculant, a lubricant, a buffer, abiocide, and a weighting agent. 13: The drilling fluid composition ofclaim 1, which is substantially free of a fluid loss additive, a densityreducing agent, and a rheology modifying agent, other than the treateddate pit particles and the viscosifier. 14: A method of making thedrilling fluid composition of claim 1, comprising: contacting dried datepit particles with an organic solvent to remove oils and form de-oileddate pit particles; mixing the de-oiled date pit particles with a baseand water to form an alkaline mixture; subjecting the alkaline mixtureto a freeze/thaw process and optionally adding an acid to form afreeze/thaw mixture comprising the treated date pit particles in water;and adding the freeze/thaw mixture to the viscosifier and the aqueousbase fluid to form the drilling fluid composition. 15: The method ofclaim 14, wherein the organic solvent is at least one selected from thegroup consisting of pentane, hexane, methanol, and ethanol. 16: Themethod of claim 14, wherein the base is sodium hydroxide and the acid,when added, is acetic acid or sulfuric acid. 17: The method of claim 14,wherein the freeze/thaw process comprises subjecting the alkalinemixture to a temperature of −20° C. or below for at least 4 hours toform a frozen mixture, thawing the frozen mixture at a temperature of20-50° C.; and agitating for at least 15 minutes to form the freeze/thawmixture. 18: A process for drilling a subterranean geological formation,comprising: drilling the subterranean geological formation with a drillbit to form a wellbore; and injecting the drilling fluid composition ofclaim 1 into the subterranean geological formation through the wellbore.19: The process of claim 18, wherein the treated date pit particles areii) treated with a base, and the drilling fluid composition is injectedinto the subterranean geological formation through the wellbore tomaintain a pressure in the wellbore that is higher than a staticpressure of the subterranean geological formation. 20: The process ofclaim 18, wherein the treated date pit particles are ii) treated withboth a base and an acid, and the drilling fluid composition is injectedinto the subterranean geological formation through the wellbore tomaintain a pressure in the wellbore that is lower than a static pressureof the subterranean geological formation.